Recompaction of Sand Reservoirs

ABSTRACT

Methods and systems for recompacting a hydrocarbon reservoir to prevent override of a fill material are provided. An exemplary method includes detecting a slurry override condition and reducing a pressure within the reservoir so as to reapply a stress from an overburden.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the priority benefit of U.S. Provisional PatentApplication 61/500,456 filed 23 Jun. 2011 entitled RECOMPACTION OF SANDRESERVOIRS, the entirety of which is incorporated by reference herein.

FIELD

The present techniques are directed to recompacting sand reservoirs.More specifically, the recompaction may be used to mitigate sandoverride in such reservoirs.

BACKGROUND

This section is intended to introduce various aspects of the art, whichmay be associated with exemplary embodiments of the present techniques.This discussion is believed to assist in providing a framework tofacilitate a better understanding of particular aspects of the presenttechniques. Accordingly, it should be understood that this sectionshould be read in this light, and not necessarily as admissions of priorart.

Modern society is greatly dependant on the use of hydrocarbons for fuelsand chemical feedstocks. Hydrocarbons are generally found in subsurfacerock formations that can be termed “reservoirs.” Removing hydrocarbonsfrom the reservoirs depends on numerous physical properties of the rockformations, such as the permeability of the rock containing thehydrocarbons, the ability of the hydrocarbons to flow through the rockformations, and the proportion of hydrocarbons present, among others.Easily harvested sources of hydrocarbons are dwindling, leaving lessaccessible sources to satisfy future energy needs. However, as the costsof hydrocarbons increase, these less accessible sources becomeeconomically attractive.

Recently, the harvesting of oil sands to remove bitumen has become moreeconomical. Hydrocarbon removal from the oil sands may be performed byseveral techniques. For example, a well can be drilled to an oil sandreservoir and steam, hot air, solvents, or a combination thereof, can beinjected to release the hydrocarbons. The released hydrocarbons may thenbe collected by other wells and brought to the surface. In anothertechnique, strip or surface mining may be performed to access the oilsands, which can then be treated with hot water or steam to extract theoil. However, this technique produces a substantial amount of waste ortailings that must be disposed.

Another process for harvesting oil sands, which may generate lesssurface waste, is the slurrified hydrocarbon extraction process. In theslurrified hydrocarbon extraction process, the entire contents of areservoir, including sand and hydrocarbon, can be extracted from thesubsurface via wellbore for processing at the surface to remove thehydrocarbons. The tailings are then reinjected via wellbores back intothe subsurface to prevent subsidence of the reservoir and allow theprocess to sweep the hydrocarbon bearing sands from the reservoir to thewellbore producing the slurry.

U.S. Pat. No. 5,832,631 to Herbolzheimer, et al., discloses one suchslurrified hydrocarbon recovery process that uses a slurry that isinjected into reservoir. In this process, hydrocarbons that are trappedin a solid media, such as bitumen in oil sands, can be recovered fromdeep formations. The process is performed by relieving the stress of theoverburden and causing the formation to flow from an injection well to aproduction well, for example, by fluid injection. A oil sand/watermixture is recovered from the production well. The bitumen is separatedfrom the sand and the remaining sand is reinjected in a water slurry.

International Patent Application Publication No. WO/2007/050180, by Yaleand Herbolzheimer, discloses an improved slurrified heavy oil recoveryprocess. The application discloses a method for recovering heavy oilthat includes accessing a subsurface formation from two or morelocations. The formation may include heavy oil and one or more solids.The formation is pressurized to a pressure sufficient to relieve theoverburden stress. A differential pressure is created between the two ormore locations to provide one or more high pressure locations and one ormore low pressure locations. The differential pressure is varied withinthe formation between the one or more high pressure locations and theone or more low pressure locations to mobilize at least a portion of thesolids and a portion of the heavy oil in the formation. The mobilizedsolids and heavy oil then flow toward the one or more low pressurelocations to provide a slurry comprising heavy oil, water and one ormore solids. The slurry comprising the heavy oil and solids is flowed tothe surface where the heavy oil is recovered from the one or moresolids. The one or more solids are recycled to the formation, forexample, as backfill.

The method discussed above converts the hydrocarbon bearing reservoirinto a formation resembling a moving bed. When the reservoir movestoward the producer wells, void space is filled by the reinjected cleanslurry stream. The reinjected stream must have permeability that ishigher than the relative permeability to water of the target formation.Thus, the slurry is not pushed, but rather dragged by the percolatingfluid flow.

As mentioned, the formation can be conditioned to relieve the pressureof the overburden, for example, by injecting water until the pressurenormalizes. This is described in U.S. Patent Application Publication No.2010/0218954 by Yale, et al., entitled “Application of ReservoirConditioning in Petroleum Reservoirs.” The application provides methodsfor recovering heavy oil. The process includes conditioning a reservoirof interest, then initially producing fluids and particulate solids suchas sand to increase reservoir access. The initial production of a slurrymay generate high permeability channels or wormholes in the formation,which may be used for hydrocarbon production processes such as cold flow(CHOPS) or enhanced production processes such as steam assisted gravitydrainage (SAGD) or vapor extraction (VAPEX) techniques.

Most processes to recover hydrocarbons from subsurface formationsinvolve the reduction in fluid pressure in the reservoir which can leadto compaction of the formation. The magnitude of this compaction isdependent upon the degree of pressure reduction and the stiffness of theformation. The compaction is sometimes used to help drive out fluidsfrom the formation into the production wells and to the surface.Injection of fluid into formations during hydrocarbon recovery is alsooften used to either keep fluid pressure up (to help maintain sufficientpressure to drive fluids to the production wells) or to help sweep thein-situ hydrocarbons to the production wells. In general, significantcompaction in reservoir formations is avoided due to the problems it cancause with the stability of wellbores into these formations andpotential problems with the subsidence of the surface.

SUMMARY

An embodiment provides a method for recompacting a reservoir comprisingdetecting a slurry override condition and reducing a pressure within thereservoir so as to reapply a stress from an overburden to mitigateoverride during a hydrocarbon recovery process.

Another embodiment provides a method for harvesting a hydrocarbon from asand reservoir. The method includes detecting a slurry overridecondition and reducing a pressure within the sand reservoir so as toreapply a stress from an overburden onto the reservoir sand.

Another embodiment provides a system for recompacting a reservoir,comprising an injection well, wherein the injection well is configuredto inject a slurry comprising sand and fluid into the reservoir and aproduction well, wherein the production well is configured to produce aslurry comprising sand and hydrocarbon from the reservoir, wherein theinjection well, the production well, or both is configured to allowrecompaction of the reservoir.

DESCRIPTION OF THE DRAWINGS

The advantages of the present techniques are better understood byreferring to the following detailed description and the attacheddrawings, in which:

FIG. 1 is a diagram showing the use of a slurrified heavy oil reservoirextraction process to harvest hydrocarbons from a reservoir, such as anoil sands deposit;

FIG. 2(A) is a schematic of the initial state with the reservoir understress from the pressure of the overburden;

FIG. 2(B) is a schematic of the conditioning process used to remove thestress of the overburden from the reservoir;

FIG. 2(C) is a schematic of a slurry production process, as describedwith respect to FIG. 1;

FIG. 2(D) is a schematic of an override condition, in which a portion ofthe mixed slurry overrides the reservoir and follows a direct path fromthe injection well to the production well;

FIG. 3 is a schematic of a recompaction process that recompacts the sandbed by producing fluid from both the injection wells and productionwells;

FIG. 4 is a schematic of a recompaction process that recompacts the sandbed by shutting in the production well and producing fluid from theinjection well;

FIG. 5 is a schematic of another recompaction process that recompactsthe sand bed by shutting in the injection well and allowing fluid to beproduced from the production well;

FIG. 6 is a schematic of a recompaction process based on an controlledimbalance between the slurry injection rate and the reservoir productionrate;

FIG. 7 is a diagram showing a pattern of injection wells and productionwells over a hydrocarbon field;

FIG. 8(A) is a schematic of production changes to injection wells andproduction wells that may be performed to recompact a target region of areservoir;

FIG. 8(B) is another schematic of production changes to injection wellsand production wells that may be performed to recompact a target regionof a reservoir;

FIG. 9 is a process flow diagram of a method for producing hydrocarbonsfrom a sand reservoir;

FIG. 10 is a drawing of a 210 cm diameter sand bed showing a coloredsand flow (indicated by the hash marked area) through each of fourinjection arms;

FIG. 11 is a drawing of a resistivity image of the 210 cm diametersandpack, illustrating loss of flow into one arm; and

FIG. 12 is a drawing of the resistivity image of a 210 cm diametersandpack, illustrating restoration of flow into the arm afterrecompaction.

DETAILED DESCRIPTION

In the following detailed description section, specific embodiments ofthe present techniques are described. However, to the extent that thefollowing description is specific to a particular embodiment or aparticular use of the present techniques, this is intended to be forexemplary purposes only and simply provides a description of theexemplary embodiments. Accordingly, the techniques are not limited tothe specific embodiments described below, but rather, include allalternatives, modifications, and equivalents falling within the truespirit and scope of the appended claims.

At the outset, for ease of reference, certain terms used in thisapplication and their meanings as used in this context are set forth. Tothe extent a term used herein is not defined below, it should be giventhe broadest definition persons in the pertinent art have given thatterm as reflected in at least one printed publication or issued patent.Further, the present techniques are not limited by the usage of theterms shown below, as all equivalents, synonyms, new developments, andterms or techniques that serve the same or a similar purpose areconsidered to be within the scope of the present claims.

“Bitumen” is a naturally occurring heavy oil material. Generally, it isthe hydrocarbon component found in oil sands. Bitumen can vary incomposition depending upon the degree of loss of more volatilecomponents. It can vary from a very viscous, tar-like, semi-solidmaterial to solid forms. The hydrocarbon types found in bitumen caninclude aliphatics, aromatics, resins, and asphaltenes. A typicalbitumen might be composed of:

19 wt. % aliphatics (which can range from 5 wt. %-30 wt. %, or higher);

19 wt. % asphaltenes (which can range from 5 wt. %-30 wt. %, or higher);

30 wt. % aromatics (which can range from 15 wt. %-50 wt. %, or higher);

32 wt. % resins (which can range from 15 wt. %-50 wt. %, or higher); and

some amount of sulfur (which can range in excess of 7 wt. %).

In addition bitumen can contain some water and nitrogen compoundsranging from less than 0.4 wt. % to in excess of 0.7 wt. %. The metalscontent, while small, must be removed to avoid contamination of theproduct synthetic crude oil (SCO). Nickel can vary from less than 75 ppm(part per million) to more than 200 ppm. Vanadium can range from lessthan 200 ppm to more than 500 ppm. The percentage of the hydrocarbontypes found in bitumen can vary.

“Clark hot water extraction process” (“CHWE”) was originally developedfor releasing bitumen from oil sands, based on the work of Dr. K. A.Clark, and discussed in a paper by Corti, et al., “Athabasca MineableOil Sands: The RTR/Gulf Extraction Process Theoretical Model of BitumenDetachment,” The 4th UNITAR/UNDP International Conference on Heavy Crudeand Tar Sands Proceedings, vol. 5, Edmonton, AB, Aug. 7-12, 1988, pp.41-44, 71. The process uses vigorous mechanical agitation of the oilsands with water and caustic alkali to disrupt the granules and form aslurry, after which the slurry is passed to a separation tank for theflotation of the bitumen, or other hydrocarbons, from which the bitumenis skimmed. The process may be operated at ambient temperatures, with aconditioning agent being added to the slurry. Earlier methods usedtemperatures of 85° C., and above, together with vigorous mechanicalagitation and are highly energy inefficient. Chemical adjuvants,particularly alkalis, have to be utilized to assist these processes.

The “front end” of the CHWE, leading up to the production of cleaned,solvent-diluted bitumen froth, will now be generally described. Theas-mined oil sand is firstly mixed with hot water and caustic in arotating tumbler to produce a slurry. The slurry is screened, to removeoversize rocks and the like. The screened slurry is diluted withadditional hot water and the product is then temporarily retained in athickener vessel, referred to as a primary separation vessel (“PSV”). Inthe PSV, bitumen globules contact and coat air bubbles which have beenentrained in the slurry in the tumbler. The buoyant bitumen-coatedbubbles rise through the slurry and form a bitumen froth. The sand inthe slurry settles and is discharged from the base of the PSV, togetherwith some water and a small amount of bitumen. This stream is referredto as “PSV underflow.” “Middlings,” including water containingnon-buoyant bitumen and fines, collect in the mid-section of the PSV.

The froth overflows the lip of the vessel and is recovered in a launder.This froth stream is referred to as “primary” froth. It typicallycomprises 65 wt. % bitumen, 28 wt. % water, and 7 wt. % particulatesolids.

The PSV underflow is introduced into a deep cone vessel, referred to asthe tailings oil recovery vessel (“TORV”). Here the PSV underflow iscontacted and mixed with a stream of aerated middlings from the PSV.Again, bitumen and air bubbles contact and unite to form buoyantglobules that rise and form a froth. This “secondary” froth overflowsthe lip of the TORV and is recovered. The secondary froth typicallycomprises 45 wt. % bitumen, 45 wt. % water, and 10 wt. % solids. Theunderflows from the TORV, the flotation cells and the dilutioncentrifuging circuit are typically discharged as tailings into a pondsystem. As used herein, the tailings are sources of particulate streamsthat may be separated into two or more substreams, for example,including particles of different sizes. Any discussions of particleswill include tailings and vice-versa. In embodiments of the presenttechniques, the tailings are reinjected back into the formation asbackfill. The reinjection both prevents subsidence as material isremoved from the reservoir and also lowers environmental issues from thewaste tailings. Water removed from the tailings during the reinjectionprocess may be recycled for use as plant process water.

“Facility” as used in this description is a tangible piece of physicalequipment through which hydrocarbon fluids are either produced from areservoir or injected into a reservoir, or equipment which can be usedto control production or completion operations. In its broadest sense,the term facility is applied to any equipment that may be present alongthe flow path between a reservoir and its delivery outlets. Facilitiesmay comprise production wells, injection wells, well tubulars, wellheadequipment, gathering lines, manifolds, pumps, compressors, separators,surface flow lines, sand processing plants, and delivery outlets. Insome instances, the term “surface facility” is used to distinguish thosefacilities other than wells. A “facility network” is the completecollection of facilities that are present in the model, which wouldinclude all wells and the surface facilities between the wellheads andthe delivery outlets.

A “hydrocarbon” is an organic compound that primarily includes theelements hydrogen and carbon, although nitrogen, sulfur, oxygen, metals,or any number of other elements may be present in small amounts. As usedherein, hydrocarbons generally refer to components found in bitumen, orother oil sands.

“Permeability” is the capacity of a rock to transmit fluids through theinterconnected pore spaces of the rock; the customary unit ofmeasurement is the millidarcy. The term “relatively permeable” isdefined, with respect to formations or portions thereof, as an averagepermeability of 10 millidarcy or more (for example, 10 or 100millidarcy). The term “relatively low permeability” is defined, withrespect to formations or portions thereof, as an average permeability ofless than about 10 millidarcy.

“Pressure” is the force exerted per unit area by the gas on the walls ofthe volume. Pressure can be shown as pounds per square inch (psi).“Atmospheric pressure” refers to the local pressure of the air.“Absolute pressure” (psia) refers to the sum of the atmospheric pressure(14.7 psia at standard conditions) plus the gage pressure (psig). “Gaugepressure” (psig) refers to the pressure measured by a gauge, whichindicates only the pressure exceeding the local atmospheric pressure(i.e., a gauge pressure of 0 psig corresponds to an absolute pressure of14.7 psia). The term “vapor pressure” has the usual thermodynamicmeaning. For a pure component in an enclosed system at a given pressure,the component vapor pressure is essentially equal to the total pressurein the system.

As used herein, “pressure gradient” represents the pressure differencesdivided by the distance between the locations where those pressuredifferences are measured. Pressure gradient is a measure of drivingforce moving the sand through the reservoir or the pressure movingslurries through a pipe.

As used herein, “overburden stress” is the stress that the overburdenapplies to the sands within the reservoir due to its weight. Overburdenstress may be considered to be the effective stress applied by theoverburden, e.g., the total stress of the overburden minus the fluidpressure within the reservoir sand. As such it is a measure of thestresses the sand grains in the reservoir sand exert on each other dueto the weight of the overburden.

As used herein, “override” is a condition where the injected fluids orslurries flow from injector to producer with little or reduced movementof the hydrocarbon bearing sand in between the injector and producer.This override is generally the overriding of the injected fluids orslurries over the top of the hydrocarbon bearing sand due to the densityof the reinjected material and/or the lack overburden stress on thatportion of the hydrocarbon bearing sands in the reservoir. However, inthis context, override may include any bypass, whether over the top ofthe sand, under the sand, or through the sand, where the reinjectedmaterials pass from the injector to producer with significantly reducedpressure gradient between the injector and producer than before overrideand with significantly reduced or nearly zero movement of thehydrocarbon bearing sand towards the producing well in the region of theoverride or bypass.

As used herein, a “reservoir” is a subsurface rock formation from whicha production fluid can be harvested. The rock formation may includegranite, silica, carbonates, clays, and organic matter, such as oil,gas, or coal, among others. Reservoirs can vary in thickness from lessthan one foot (0.3048 m) to hundreds of feet (hundreds of m). Thepermeability of the reservoir provides the potential for production. Asused herein a reservoir may also include a hot dry rock layer used forgeothermal energy production. A reservoir may often be located at adepth of 50 meters or more below the surface of the earth or theseafloor.

A “sand filter” or well screen is a zone of perforated material that iseither built into an end of a well pipe, or fitted as a sleeve over avery coarsely perforated part of the pipe. The well screen can be madefrom wire mesh, wire wound, perforated plate, or porous metal fibermaterial. The design of the well screen will be tailored to the size ofthe solid particles to be blocked, which is generally 50 μm or more.Generally, the sand in a heavy oil reservoir can vary in particle sizefrom about 62.5 μm to greater than about 500 μm, so the screen aperturemay be important. If the aperture is too large in relation to the sand'sparticle size, then a fluid rate will be higher, but too much sand willpenetrate the screen. If the aperture is too close to the size of theparticles, then the fluid may be clean, but the flow rate may be low andthe screen may quickly block. As used herein, a sand filter may beincluded as a segment of a pipe in an injection well or a productionwell that is used during a recompaction process. The resulting fluidflow may not be completely free of sand, but may be substantially freeof sand, e.g., without containing enough sand to effect the reservoirsand content.

“Substantial” when used in reference to a quantity or amount of amaterial, or a specific characteristic thereof, refers to an amount thatis sufficient to provide an effect that the material or characteristicwas intended to provide. The exact degree of deviation allowable may insome cases depend on the specific context.

A “wellbore” is a hole in the subsurface made by drilling or inserting aconduit into the subsurface. A wellbore may have a substantiallycircular cross section or any other cross-sectional shape, such as anoval, a square, a rectangle, a triangle, or other regular or irregularshapes. As used herein, the term “well”, when referring to an opening inthe formation, may be used interchangeably with the term “wellbore.”Further, multiple pipes may be inserted into a single wellbore, forexample, to limit frictional forces in any one pipe.

Overview

As previously mentioned, hydrocarbons can be harvested from sandreservoirs by producing a slurry that includes both sand andhydrocarbons from a production well. The sand is processed to removehydrocarbons, and reinjected as a slurry into the reservoir. However, incertain situations, the reinjected slurry can override the reservoir dueto its lower density relative to the in-situ density of the reservoirand/or reduction in stress on the reinjection sand and/or excessivefluid in the reinjected slurry. In these cases, the reinjected slurrycan travel directly from the injection wells to the production wells,decreasing or eliminating the pressure gradients needed to move thein-situ reservoir sand from the injector to producer. This is likely toreduce the ultimate recovery of the process, hurting the economics ofthe project. Further, the overall recovery from the slurrified heavy oilrecovery process may be decreased by slurry override. Embodiments of thepresent invention provide a method and a system for recompacting a sandreservoir to prevent a lower viscosity slurry from overriding a lowerlayer and move from an injection well to a production well whilebypassing hydrocarbon.

For effective injection of tailings, two conditions can be met. First,the permeability of the backfill solids can be controlled within apredetermined range of about 0.5 to about 100 times of the initialpermeability of the injected fluid through the porous material of thesubsurface formation into which the mixture is injected. Second, theslurry rheology can be controlled to manage pipe pressure losses. Whenboth criteria are met, the backfill may be placed correctly, waterconsumption can be optimal, and subsidence may be prevented. More diluteslurries, i.e., higher water fraction, are sometimes needed in thisinitial startup phase as the extra water may helps to start the process.This leads to the potential for override of the less dense slurry if theexcess water does not flow away from the reinjected slurry fast enoughor the less dense slurry is injected for too long of a period.

Recompaction to Improve Performance

Some embodiments of current invention include various mining or civilengineering operations which rely on backfilling, such as reinjection orreplacement, of part or the whole of produced formation underground. Inparticular in situ heavy oil mining operations, such as a slurrifiedheavy oil reservoir extraction method shown in FIG. 2, may benefit fromthe current invention.

FIG. 1 is a diagram 100 showing the use of a slurrified heavy oilreservoir extraction process to harvest hydrocarbons from a reservoir,such as an oil sands deposit. The slurry recompaction techniquesdescribed herein are not limited to the slurrified reservoir process butmay be used with any number of other processes. For example, thetechniques described herein may be used to recompact a separationcolumn, recompact a slurry fill in a subsurface cavity, or perform anynumber of other recompaction operations. In the diagram 100, a reservoir102 is accessed by an injection well 104 and a production well 106drilled through an overburden 108 above the reservoir 102.

The reservoir is a subsurface formation that may be at a depth greaterthan about 50 meters. Water injection into the wells 104 and 106 can beused to raise the fluid pressure in the reservoir 102 and relieve thestress on the reservoir 102 from the overburden 108. The pressure atwhich the stress is relieved on the reservoir may be termed theconditioning pressure, as that is the pressure at which the reservoir isdeemed sufficiently conditioned to allow sand flow from the reservoir.The conditioning pressure depends on the pressure from the overburden108, e.g., due to the depth of the reservoir 102, and may be about 50 toabout 1000 psi greater than the initial pressure. After the relief ofoverburden stress, a water and sand mixture can be injected through theinjection well 104, for example, from a pumping station 110 at thesurface 112. At the same time, hydrocarbon containing materials 114,such as oil sands, can be harvested from the reservoir 102, for example,through another pumping station 116. The hydrocarbon containingmaterials 114 may be processed in a facility 118 to remove at least aportion of the hydrocarbons 120. The hydrocarbons 120 can be sent toother facilities for refining or further processing. The cleanedtailings can be used to form a mixed slurry 122, including water andsand or other particulates, which may then be backfilled, i.e.,reinjected into the reservoir 102, for example, to prevent subsidence ofthe surface 112. The injection well 104 and production well 106 aregenerally limited to single connections to the reservoir 102, butmultiple injection and production wells 104 and 106 are often used overa reservoir.

The method converts the hydrocarbon bearing sands of the reservoir 102into a formation resembling a moving bed that includes sand andhydrocarbon. When the reservoir 102 moves toward the production well106, the void space can be continuously filled by a reinjected cleanslurry stream, which can include clay, silt, sand, and fluid, from theinjection well 104.

The slurry fill process, described above, may also influence the densityof the sand in the reservoir 102. In combination with the initialconditioning step, this process may create a lower density slurry in anupper part of the reservoir 102, which could allow an injected mixedslurry 122 to at least partially override the hydrocarbon bearing sandand pass through the reservoir 102 without moving the hydrocarbonbearing slurry through the reservoir. The slurrified heavy oil recoveryprocess is discussed further with respect to FIGS. 2(A)-(D).

FIG. 2(A) is a schematic of the initial state with the reservoir 102under stress from the pressure of the overburden 108. In FIGS. 2(A)-(D),like numbered items are as discussed with respect to previous figures.Two wells may be completed to the reservoir 102, an injection well 104and a production well 106. The wells 104 and 106 are not limited toinjection or production, but may be converted as needed to serve eitherpurpose, for example, during a conditioning or recompaction process.Further, as discussed further with respect to FIGS. 7 and 8, a number ofinjection wells 104 and production wells 106 may be used to access thereservoir 102.

FIG. 2(B) is a schematic of the conditioning process used to remove thestress of the overburden 108 from the reservoir 102. The conditioning isgenerally performed by fluid injection, for example, through one or moreof the wells 104 and 106, as indicated by arrows 202. Once conditioningis completed, the stresses on the reservoir 102 are balanced, andfrictional forces, which may tend to prevent the reservoir from beingharvested, are decreased enough to allow the reservoir 102 to move.After this conditioning process, there remains some limited overburdenstress on the hydrocarbon bearing reservoir sands. The magnitude of thisstress is generally small (generally in the range of 10 to 400 kPa outof the 1 MPa to 10 MPa overburden stress that would have been on thesands before conditioning.

FIG. 2(C) is a schematic of a slurry production process, as describedwith respect to FIG. 1. In the production process, the clean, mixedslurry 122 is injected into the reservoir 102, creating a zone 204containing the mixed slurry 122, which causes the reservoir 102 to slidefrom the vicinity of the injection well 104 to the vicinity of theproduction well 106, as indicated by arrow 206. From the production well106, the hydrocarbon containing materials 114 can be produced.

FIG. 2(D) is a schematic of an override condition, in which a portion208 of the mixed slurry 122 overrides the reservoir 102 and follows adirect path from the injection well 104 to the production well 106. Inthis case, the injected slurry bypasses the hydrocarbon containingmaterials of the reservoir 102. Based on experiments, override may occurbecause the overburden stresses on the sands within the overriding mixedslurry nearly completely disappear, for example, due to the presence ofexcess fluid pressure in the region or to the overburden stresses beingsupported by nearby non-moving portions of the reservoir sand. Theoverride condition may be directly detected by the composition of theextracted material. The override condition may also be detected by asignificant drop in the pressure gradient between the injector andproducer, since it may take less pressure to drive the overridingmaterial between injector and producer, than to drive the reinjectedsands and hydrocarbon bearing sands between injector and producer whenoverride is not occurring. Further, the loss of pressure gradientbetween injector and producer due to override may slow down or stop themovement of the hydrocarbon bearing sand and, thus, reduce theproduction of hydrocarbon bearing sand from the area in which overrideis occurring.

In an embodiment, override may be mitigated by recompaction of thereservoir sand. For example, the reservoir 102 may be either partiallyrecompacted or returned to its original stress state. In someembodiments, the recompaction may be directed to the portion 208 of themixed slurry 122 that is overriding the in-situ material. Therecompaction of the reservoir 102 or the portion 208 may be used tobring the density of sand throughout the reservoir 102 to nearly thesame state.

The recompaction may be performed by reducing the pressure in thereservoir 102, for example, by slowing or stopping the injection of themixed slurry 122 or production of the hydrocarbon bearing materials 114,while allowing water production from the injection wells 104, productionwells 106, or from both. This allows the stress from the overburden 108to be at least partially reapplied to the reservoir 102, recompacting atleast a portion of the sand in the reservoir 102. The reservoir pressureafter the recompaction may be higher than the initial pressure in thereservoir 102, or may be at the initial pressure of the reservoir 102.In an embodiment, the reinjected sand in the portion 206 of the slurrymixture 122 that is overriding the reservoir 102 may be recompacted,sealing the path of the slurry override. In another embodiment, thepressure in the reservoir could be allowed to bleed off to other partsof the reservoir that may be at lower pressure.

The slurrified heavy oil recovery process can then restarted byrepeating the conditioning phase discussed with respect to FIG. 2(B).The conditioning phase may be accomplished in a shorter times due to thepresence of some higher permeability reinjected slurry and the higherwater saturation of the recompacted reservoir system versus the originalin-situ reservoir system and restarting slurry production andreinjection. As the sands have been recompacted, it is believed theprocess will allow ultimate recoveries to be similar to what they wouldhave been if override never occurred. The techniques that may be usedfor recompacting the reservoirs in various embodiments is discussed ingreater detail with respect to FIGS. 3-6.

FIG. 3 is a schematic of a recompaction process 300 that recompacts thesand bed by producing fluid from both the injection wells 104 andproduction wells 106. In FIG. 3, like numbered items are as discussedwith respect to previous figures. The fluid production, indicated byarrows 302, may be performed by allowing flow at a reduced rate, whichmay lower entrainment of sand. The fluid production 302 may also beperformed through a sand filter, such as a limited entry perforation(LEP) segment. The LEP may be included as a portion of the well duringthe initial completion or may be placed in one or both wells 104 and 106at a later time.

FIG. 4 is a schematic of a recompaction process 400 that recompacts thesand bed by shutting in the production well 106 and producing fluid 302from the injection well 104. In FIG. 4, like numbered items are asdiscussed with respect to previous figures. As in the previousrecompaction process, the injection well 104 may have an LEP segment toallow the fluid production 302 without entrained sand. However, theproportion of fines in the reinjected slurry mixture 122 may be lowerthan in the sand of the reservoir 102. This may allow for higherproduction rates of fluid 302 without solid entrainment from theinjection well 104 as the zone 204 comprising the mixed slurry 122 mayact as a sand filter. In addition, since the reinjected sand would havesubstantially no hydrocarbons, with the possible exception of a smallamount left over after the surface extraction process, the ability toproduce water out of the injection wells would likely be easier thanproducing it out of the production wells due to the higher permeabilityto water of the sands around the injection well as compared to thataround the producing wells.

FIG. 5 is a schematic of another recompaction process 500 thatrecompacts the sand bed by shutting in the injection well 104 andallowing fluid 302 to be produced from the production well 106. In FIG.5, like numbered items are as discussed with respect to previousfigures. As described herein, a LEP segment may be included in theproduction well 106 to allow the fluid 302 to be produced withoutentrained sand. In addition, other methods may be used to prevent sandproduction while water production is being attempted. These couldinclude, but are not limited to, sand screens, slotted liners, or gravelpacks in addition to the LEPs mentioned earlier.

The recompaction does not have to be performed by completely shutting inthe wells 104 or 106. In an embodiment of the process, slurry injectioncan be continued, while only fluid is withdrawn from the production well106 rather than a fluid and sand slurry, as described with respect toFIG. 6. In an embodiment, slurry injection could continue in someinjection wells while other injection wells are used to produce fluidonly for reasons stated above.

FIG. 6 is a schematic of a recompaction process 600 based on acontrolled imbalance between the slurry injection rate and the reservoirproduction rate. In FIG. 6, like numbered items are as discussed withrespect to previous figures. This may be performed using any number ofcombinations of injection and production rates. For example, theinjection rate of the slurry may be decreased, as indicated by thedotted arrow 602, while the production rate, indicated by the solidarrow 604 is held constant.

In other embodiments, the injection rate 602 of the slurry may be heldconstant while only fluid is produced from the production well 106. Inthis embodiment, a LEP segment may be included in the production well106 to assist in the production of fluid without entrained sand. Theproduction of only fluid while injecting denser slurry allows thereinjected material in the override area 208 to become denser and thussupport the overburden stress.

FIG. 7 is a diagram showing a pattern 700 of injection wells 702 andproduction wells 704 over a hydrocarbon field 706. The hydrocarbon field706 generally overlies a single reservoir 102, for example, as discussedabove. The pattern 700 may generally be referred to as a “five-spotpattern,” in which four injection wells 702 surround a centralproduction well 704. Generally, the pattern 700 can be repeated multipletimes across a hydrocarbon field 706, so that the number of injectionwells 702 and production wells 704 are matched, which assists withmaintaining a mass balance of material entering and exiting thereservoir. As shown in FIG. 7, the pattern 700 may be regularly spacedacross a field. In other embodiments, the wells 702 and 704 may beirregularly spaced, for example, placed to improve interaction with thereservoir geometry. Any number of other patterns may be used inembodiments.

While the slurrified heavy oil recovery method relies on multiple,repeated patterns of injectors and producers, the selected recompactionscheme does not necessarily need to be applied to the entire reservoir102. For example, if an override condition is detected only in onportion of the reservoir 102, a recompaction process may be implementedonly on that section. This is discussed further with respect to variouspatterns in FIG. 8. The patterns are not limited to those shown in FIG.8, but may be implemented using any number of patterns. Apattern-by-pattern decision can be made based on local production andinjection information, for example, depending on the size, shape, orreservoir configuration in the area of the override.

FIG. 8 (A) is a schematic of production changes to injection wells andproduction wells that may be performed to recompact a target region 800of a reservoir. In this example, production rates for injection wells802 and production wells 804 outside of the target region 800 may not bechanged. However, production wells 806 surrounding the target region 800may be operated at a reduced rate and wells 808 within the target region800 may be shut-in. This may allow a slow subsidence of the targetregion, for example, by fluid draining to other regions or to thesurrounding formations, providing recompaction of the sand bed withinthe target region 800.

FIG. 8(B) is another schematic of production changes to injection wellsand production wells that may be performed to recompact a second targetregion 810 of a reservoir. In this example, the second target region 810includes the opposing “arms” of a five-spot pattern. A partialrecompaction, for example, a few psi to a few tens of psi, may beperformed by shutting in a single producer 812 and two opposinginjection wells 814, and reducing rates from the surrounding productionwells 806.

The techniques are not limited to the patterns and embodiments shownabove, but may use any combinations of wells that are shut-in, producingat reduced rates, or merely producing fluid. For example, production orproduction and injection may be shut down in an area and the pressuresin the area may be allowed to equilibrate before starting up productionand injection again. This may be performed to mitigate the pressuregradients causing an override.

The techniques described herein allow for the re-application orre-distribution of overburden stresses on the reservoir sand. In somecases, such as a full or nearly full reapplication of overburdenstresses, the stresses are redistributed so that certain parts of thereservoir sand, such as the non-moving sections, are compacted. This mayredistribute the stresses on those portions of the reservoir to theparts of the sand where slurry injection and slurry production wereoccurring. In other cases, the redistribution of stresses and porepressure may be milder and the override can be avoided upon restart dueto the bleed off of fluid pressures from the override area as much as bythe redistribution of stresses.

In addition to reducing fluid pressure and recompacting the sand, thetechniques described herein have the beneficial outcome of making thesand, fluid pressures, and stresses on the sand in the reservoir morehomogenous. The processes discussed above may lead to inhomogeneities insand permeability or pressure or stress distributions, which can lead tooverride or bypass. As such, the homogenization of those properties ofthe sand in the reservoir also act as a method to help prevent overrideonce injection and production is restarted.

FIG. 9 is a process flow diagram of a method 900 for producinghydrocarbons from a sand reservoir. The method 900 begins at block 902when an injection well is completed to a reservoir. Although theinjection well will generally be used for slurry injection, theinjection well may also include a limited entry perforation (LEP)section, or other type of sand trap, that allows fluid to flow withoutentrained sand when selected. At block 904, a production well iscompleted to the reservoir. As in the case of the injection well, theproduction well may also have a segment containing a sand trap.

At block 906, the reservoir can be conditioned for slurry flow. This isperformed by injecting fluid into the reservoir through the injectionwells, the production wells, or both, until the pressure in thereservoir is normalized with the pressure of the overburden. Thenormalization releases friction in the reservoir, allowing the reservoirto move from the injection well to the production well.

At block 908, slurry may be injected in the injection well to cause thereservoir to flow towards the production well. At block 910, hydrocarboncontaining slurry can be produced from the reservoir through theproduction well. Produced materials can be cleaned and reinjected as amixed slurry, while the hydrocarbon may be transported for furtherprocessing. The reinjected mixed slurry replaces the material that isproduced. However, under some circumstances the reinjected mixed slurrymay override the hydrocarbon containing sands of the reservoir, leadingto the production of lower amounts of hydrocarbon than would otherwiseoccur.

At block 912, the override condition may be detected. This may beperformed using any number of techniques. For example, a sudden decreasein expected hydrocarbon from certain wells may be noted. Further, achange in particle size distribution may indicate that the injectedmixed slurry is passing directly from the injection well to theproduction well, bypassing the reservoir.

At block 914, pressure is lowered on the reservoir to recompact the sandbed. As discussed herein, this may be performed by any number oftechniques that allow increased production of fluids or slurry from thereservoir versus injection of slurry into the reservoir. For example, inan embodiment, injection may be slowed or stopped, while keepingproduction constant. In another embodiment, injection and production maybe stopped in the area of the override, while production at reducedrates continues from wells surrounding the area of the override. Inanother embodiment, injection may be halted and fluid may be producedfrom injection wells, production wells, or both.

At block 916, injection and production may be resumed. This may beproceeded by a repeat of the conditioning step to relieve pressure onthe reservoir. The conditioning step may take less time or less fluidthan the initial conditioning step. The method 900 may be repeated anynumber of times during the life of the reservoir.

EXAMPLES

The techniques described herein were tested in a laboratory at twodifferent scales, using a 25 cm diameter sandpack and a 210 cm diametersandpack as model reservoirs. The test procedures and apparatus for the210 cm diameter sandpack are as described in David P. Yale, et al.,“Large-Scale Laboratory Testing of the Geomechanics of PetroleumReservoirs,” SPE 134313, presented at the 44th US Rock MechanicsSymposium and 5th U.S.-Canada Rock Mechanics Symposium, held in SaltLake City, Utah, Jun. 27-30, 2010. The test procedures for the 25 cm aresimilar to those described in Yale et. al.

FIG. 10 is a drawing 1000 of a 210 cm diameter sand bed showing acolored sand flow (indicated by the hash marked area) through each offour injection arms 1002-1008. An injection arm is the area between anygiven injection well 1010 and the production well 1012. The colored sandwas mixed with the injected sand as a material marker. As shown in thisdrawing 1000, the tests were set up as single five-spot patterns, usingfour equidistant injector wells 1010 and a center single producer well1012. Real reservoir sands and model fluids were used to mimic actualreservoir mobility and ensure the slurrified heavy oil recoveryexperiments were representative. A similar configuration was used forthe sandbed in the 25 cm diameter cell. In this example, the flow intoall four injection arms 1002-1008 is visually illustrated, showing arestoration of flow after an override condition, as is discussed furtherwith respect to FIGS. 11 and 12.

In one such test in the 25 cm diameter cell, production of the coloredreinjected sand was observed well before mass balance calculationssuggested the majority of the in-situ sand had been produced. This, inaddition to pressure gradients measured in the cell, suggested that there-injected slurries were overriding the in-situ sands and not allowingas much of the in-situ sands to be produced. In one such test, thisoverride was observed to occur in just one of the four injection arms.In another test, this override was observed in two of the injectionarms. In these tests, the injection and production of slurries wassuspended and fluid only production was done until the fluid pressure inthe cell was reduced to nearly the same pressure as was in the cellbefore the “conditioning” portion of the test. This reapplied the stresson the sandpack in the cell that simulated the stress on a reservoirsand before the start of the “conditioning” part of a slurrified heavyoil extraction process.

After the pressure reduction and stress re-application, the conditioningwas repeated, i.e., fluid pressure raised to nearly the overburdenpressure applied to the sand. Then the slurry production and injectionprocess was restarted as described in Yale and Herbolzheimer. In thistest, the slurry production and slurry injection was able to proceed tofull production of the in-situ sand and achieve a sweep efficiency ofover 70%, i.e., 70% of the in-situ or initial sand in the area betweenthe injectors and producers was swept to and produced up the productionwell.

During two tests in the 210 cm diameter cell, recompaction was used toallow slurry injection-production to be re-started after earlybreakthrough and other problems. In one case override was observed inall four injection arms 1002-1008 after only about 20% of sweep and thusproduction was stopped. Investigation of the reason for the overridesuggested that the injected slurry had more water than usual, i.e., wasless dense than usual, and this led to the override both from theperspective of a less dense slurry but also by allowing overburdenstresses on the sands to decrease, which has been observed to lead tooverride.

Rather than decreasing the fluid pressure to initial conditions, aslightly different approach was taken where production of water only wasstarted in the production well 1012 and injection of a denser (lesswater) slurry was started in each of the four injection wells 1010.After the pressure was decreased by several psi and stresses werereasserted on the sand from the dense slurry injection, water productionwas stopped while slurry injection continued. Once fluid pressurerecovered to the levels sufficient for the start of slurryproduction/injection (i.e. full conditioning), production of slurry wasrestarted. Injection/production of slurry through to full sweep was thenachieved.

In addition to early production of colored sand, other techniques wereused to identify slurry override conditions. For example, the 210 cmdiameter cell is wired with a number of sensors for resistivity analysisof the sands in the cell. The resistivity images can be used to identifywhich injection arms are showing override conditions, for example, byinitially charging the sand bed with a high resistivity solution, thenusing a low resistivity solution for the liquid base in a slurry. Inaddition, a significant drop in the pressure gradient between theinjector and producer (as evidence by the measurement of pressure at anumber of points between the injector and producer) was seen when theoverride occurred.

FIG. 11 is a drawing of a resistivity image of a cross-section of the210 cm diameter sandpack, illustrating loss of flow through oneinjection arm 1004. In FIG. 11, like numbered items are as discussedwith respect to FIG. 10. In both FIGS. 11 and 12, a higher resistivityarea of the original sand bed is indicated by small x's, while a lowerresistivity area is indicated by small o's for the liquid slurry addedto the sandpack by the injection wells. Further, it should be understoodthat FIG. 11 is a two dimensional cross section of a three dimensionalphenomenon measured along the bottom of the sandpack. Accordingly,changes in resistivity may be greater in different layers.

Injection and production was started and sustained in the other threeinjection arms 1002, 1006, and 1008. However, it was surmised that therewas an override of the initial fluid injected into arm 1004 preventingthe establishment of a sufficient pressure gradient to move the sandbetween the injection well 1010 for injection arm 1004 and theproduction well 1012. This is seen in FIG. 11 in which the illustratedcross-section of the sandpack is below the overrride of the injected,low resistivity solution and the higher resistivity sand is not beingswept towards the production well 1012. After allowing injection andproduction in the other three arms to proceed to full sweep, a partialrecompaction was attempted to recompact the sand in the injection arm1004, and in the rest of the sandpack, sufficiently to allow for sandflow to be started in injection arm 1004.

FIG. 12 is a drawing of the resistivity image of a 210 cm diametersandpack, illustrating restoration of flow into the injection arm 1004after the recompaction. In FIG. 12, like numbered items are as discussedwith respect to FIG. 10. A recompaction of 40 psi, or 5% of theconditioning pressure, was applied to the sandpack and then the sandpackwas reconditioned to full conditioning pressure. The test was restartedand slurry injection and production was initiated successfully in allfour injection arms 1002-1008. Further, injection and production ininjection arm 1004 through to full sweep was successful postrecompaction. FIG. 10, above, shows the visual image post test of theswept sections of the original sand and the effectiveness of therecompaction.

Repeating the conditioning process to relieve the overburden stressapplied during the recompaction is required after each recompaction tobring the sandpack to the fully conditioned state needed to produce andinject slurry. Slurry production and slurry reinjection were thenrestarted, with the vast majority of the subsequent production beingfrom the initial, in-situ material, which indicated successful healingof the override in the various examples above.

The process was run until normal breakthrough occurred, e.g., when thevast majority of the production was of the reinjected material.Examination of the sandpacks after the test showed a high recoveryfactor, which was similar to results from tests where override did notoccur. There was no particular evidence in the recompacted sandpack thatoverride had ever occurred.

The examples above suggest that the recompaction process can be used ina number of different embodiments, e.g., a very small amount ofrecompaction, a moderate amount of recompaction, or a full recompactionto the initial reservoir conditions that existed before the conditioningprocess was first applied to the reservoir. The examples show that therecompaction can correct a range of override problems from override ofthe reinjected sand to override of just the fluid being injected. Theexamples also show that the override can occur due to a low density ofthe injected slurry or due to imbalances in the application ofoverburden stress to various portions of reservoir sand. They also showthat recompaction can be used to correct problems in just one injectionarm of a five-spot pattern to two or more injection arms of a five-spotpattern. By extension, they also suggest that the recompaction processcan be used on a single five-spot pattern or multiple five-spot patternsand to single or multiple injection arms in each of those five-spotpatterns.

The process described herein may be used in slurrified heavy oilrecovery to recompact the overriding sand to an absolute permeabilitywhich is similar enough to the permeability to water of the in-situ sandto allow the slurrified process to work. Therefore, the pressure dropacross both the overriden material and the in-situ material is similarduring subsequent injection-production and the entire sandpack isproduced rather than preferential production of the overriding material.

While the present techniques may be susceptible to various modificationsand alternative forms, the exemplary embodiments discussed above havebeen shown only by way of example. However, it should again beunderstood that the techniques is not intended to be limited to theparticular embodiments disclosed herein. Indeed, the present techniquesinclude all alternatives, modifications, and equivalents falling withinthe true spirit and scope of the appended claims.

1. A method for recompacting material in a reservoir, comprising:detecting a slurry override condition; and reducing a pressure withinthe reservoir so as to reapply a stress from an overburden.
 2. Themethod of claim 1, comprising injecting fluid into the reservoir toincrease the pressure to a conditioning pressure.
 3. The method of claim1, wherein reducing the pressure comprises lowering a slurry injectionrate while a production rate is maintained constant.
 4. The method ofclaim 1, wherein reducing the pressure comprises lowering a slurryinjection rate while increasing a production rate.
 5. The method ofclaim 1, wherein reducing the pressure comprises maintaining a constantslurry injection rate while a production rate is increased.
 6. Themethod of claim 1, wherein reducing the pressure comprises producingsubstantially only fluid from the reservoir.
 7. The method of claim 1,wherein the reservoir is an oil sands formation.
 8. The method of claim1, wherein the reduced pressure is greater than an initial reservoirpressure.
 9. The method of claim 1, wherein the reduced pressure is lessthan a conditioning pressure.
 10. A method for harvesting a hydrocarbonfrom a sand reservoir, comprising: detecting a slurry overridecondition; and reducing a pressure within the sand reservoir so as toreapply a stress from an overburden onto the reservoir sand.
 11. Themethod of claim 10, comprising: removing at least a portion of areservoir material from the sand reservoir; processing the reservoirmaterial to remove at least a portion of associated hydrocarbons andform a clean material; forming a mixture comprising at least a portionof the clean material; and reinjecting at least a portion of the mixtureinto the sand reservoir.
 12. The method of claim 10, wherein fluid orslurry are withdrawn from the sand reservoir through injection wells,production wells, or both.
 13. The method of claim 10, comprisingreducing the pressure within the sand reservoir by allowing fluid toleak-off to a surrounding formation.
 14. The method of claim 10, whereinthe pressure in the reservoir is raised up to the conditioning pressureonce sufficient recompaction has occurred to allow slurry production andslurry injection to be restarted without override.
 15. The method ofclaim 10, wherein the amount of recompaction is sufficient to restartslurry production and slurry injection without override.
 16. The methodof claim 10, comprising: injecting a slurry mixture into the reservoirthrough a plurality of injection wells; and producing a reservoirmaterial through a plurality of production wells.
 17. The method ofclaim 16, comprising reducing the pressure within the reservoir bystopping injection of the slurry mixture into at least a portion of theplurality of injection wells.
 18. The method of claim 16, comprisingreducing the pressure within the reservoir by slowing injection of theslurry mixture into at least a portion of the plurality of injectionwells.
 19. The method of claim 16, wherein fluid is withdrawn from thereservoir through the plurality of injection wells.
 20. The method ofclaim 16, wherein fluid is withdrawn from the reservoir through one ormore production wells while injection of slurry is continued through oneor more injection wells.
 21. A system for recompacting a reservoir,comprising: an injection well, wherein the injection well is configuredto inject a slurry comprising sand and fluid into the reservoir; and aproduction well, wherein the production well is configured to produce aslurry comprising sand and hydrocarbon from the reservoir, wherein theinjection well, the production well, or both is configured to allowrecompaction of the reservoir.
 22. The system of claim 21, wherein theinjection well, the production well, or both comprise at least a segmentcomprising a sand filter configured to filter sand from a producedfluid.
 23. The system of claim 21, wherein the injection well isconfigured to allow the production of fluid substantially free ofentrained sand from the reservoir.
 24. The system of claim 21, whereinthe production well is configured to allow the production of fluidsubstantially free of entrained sand from the reservoir.